In a traditional power generation process, a gaseous fuel (such as natural gas or syngas) is combusted in the presence of oxygen, producing a stream of hot, high-pressure gas. This hot, high-pressure gas is then used to drive a gas turbine, which in turn drives a generator, producing electrical energy. The exhaust gas from the turbine is still very hot and may contain as much as 50% of the energy generated by the combustion process. This remaining heat (i.e., in the form of hot exhaust fumes) is wasted.
In recent years, there has been considerable interest in combined cycle power generation to improve the energy efficiency of the process. A combined cycle power plant generates additional electricity by using the hot exhaust gas from a gas turbine to boil water to make steam. The steam, in turn, is used to drive a steam turbine, generating additional electricity. Combined cycle power generation processes are well-known in the art and are described, for example, by Rolf Kehlhofer et al. in Combined-Cycle Gas & Steam Power Plants (3rd ed., PennWell Corporation; Tulsa, Okla., 2009).
A flow diagram of a conventional gas turbine power generation process is shown in FIG. 6. In this unit, an incoming air stream 602 is compressed from atmospheric pressure to 20-30 bar in an air compressor unit 619. This compressed gas stream 603 is then combusted with the incoming fuel gas 601 (which is typically but not necessarily natural gas) in combustor 604. The hot, high-pressure gas from the combustor is then expanded through the gas turbine 606. The gas turbine 606 is mechanically linked to the air compressor 619 and an electrical power generator 611. The low-pressure exhaust gas exhaust gas 605 from the gas turbine 606 is still hot, so the energy content from this gas can optionally be recovered in a steam boiler 612 which, in a combined cycle operation, is used to make additional electricity in a secondary steam turbine.
A major issue in the design of these units is the temperature of the gas leaving the combustor. This gas stream can be too hot to allow efficient and safe use in the gas turbine. For this reason, a diluent stream of nitrogen or steam or other gas may be mixed with the air stream going to the air compressor 619. This diluent stream serves to control the temperature of stream 607 leaving the combustor. Oftentimes, the volume of this diluent stream can be equal or more than the stoichiometric volume of air required to combust the fuel.
Although nitrogen, steam, and other gases are used as a diluent, more commonly, the gas entering the combustor 604 is diluted by using an air stream that is two or even three-fold larger than the stoichiometric volume of gas required to combust the fuel. The excess air is the oxygen-containing gas that cools stream 607. In some cases, all of the air stream leaving the gas compressor 619 is sent to the combustor 604. But in other gas turbines, a portion of the compressed air may be mixed with the combustion exhaust after the combustor, shown as optional gas stream 610. This mixing option may be done before the gas turbine or within the gas turbine.
When excess air is used as the oxygen-containing gas, the exhaust gas 615 from the turbine will often only contain 4-5% carbon dioxide. Recovery of carbon dioxide from this dilute, low-pressure, yet very high-volume gas stream is expensive. In recent years, a number of turbine producers have modified the operation of these turbines by using a portion 608 of the exhaust gas 615 as the oxygen-containing gas 613 for air stream 602. Recycling the exhaust gas in this way increases the carbon dioxide concentration in the final exhaust gas from 4-5% to 8-10% and reduces the volume of gas that must be treated if carbon dioxide sequestration is to be done. This process significantly reduces the cost of carbon dioxide sequestration from the exhaust gas.
The amount of exhaust gas that can be recycled is limited by the oxygen content of the gas mixture 603 delivered to the combustion chamber 604. When excess air is used as the diluent, this gas contains about 21% oxygen; when the exhaust gas is recycled and used as a diluent, the oxygen content can drop to 15% or less. If the oxygen content drops below about 15%, changes to the turbine design will be required.
A combined cycle power generation process, in which the energy content of the hot exhaust gas from the gas turbine is recovered in a steam boiler which is used to make additional electricity in a secondary steam turbine, is inherently more expensive than the more traditional, gas turbine-only power generation process due to the additional capital equipment required. However, it is expected that the additional energy generated will eventually more than off-set the cost of the additional equipment. As a result, most new gas power plants in North America and Europe are combined cycle.
In either a traditional or combined cycle power generation process, combustion of gaseous fuels produces exhaust gases contaminated with carbon dioxide that contribute to global warming and environmental damage. Such gas streams are difficult to treat in ways that are both technically and economically practical, and there remains a need for better treatment techniques.
Combustion of gaseous fuels also generates enormous amounts of heat. Therefore, another consideration in the power generation process is to moderate the temperature of the gas entering the turbine(s), to avoid melting or otherwise damaging turbine components.
Gas separation by means of membranes is a well-established technology. In an industrial setting, a total pressure difference is usually applied between the feed and permeate sides, typically by compressing the feed stream or maintaining the permeate side of the membrane under partial vacuum.
Although permeation by creating a feed to permeate pressure difference is the most common process, it is known in the literature that a driving force for transmembrane permeation may be supplied by passing a sweep gas across the permeate side of the membranes, thereby lowering the partial pressure of a desired permeant on that side to a level below its partial pressure on the feed side. In this case, the total pressure on both sides of the membrane may be the same, the total pressure on the permeate side may be higher than on the feed side, or there may be additional driving force provided by keeping the total feed pressure higher than the total permeate pressure.
Using a sweep gas has most commonly been proposed in connection with air separation to make nitrogen or oxygen-enriched air, or with dehydration. Examples of patents that teach the use of a sweep gas on the permeate side to facilitate air separation include U.S. Pat. Nos. 5,240,471; 5,500,036; and 6,478,852. Examples of patents that teach the use of a sweep gas in a dehydration process include U.S. Pat. Nos. 4,931,070; 4,981,498; and 5,641,337.
Configuring the flow path within the membrane module so that the feed gas and sweep stream flow, as far as possible, countercurrent to each other is also known, and taught, for example in U.S. Pat. Nos. 5,681,433 and 5,843,209.
The use of a process including a membrane separation step operated in sweep mode for treating flue gas to remove carbon dioxide is taught in co-owned and copending U.S. patent application Ser. No. 12/734,941, filed Jun. 2, 2010. The use of a process including a membrane separation step operated in sweep mode for treating natural gas combustion exhaust to remove carbon dioxide is taught in co-owned and copending U.S. patent application Ser. No. 13/122,136, filed Mar. 31, 2011.